Formulations and methods for removing hydrocarbons from surfaces

ABSTRACT

The invention provides formulations for facilitating the removal of oil from a surface using a chisel composition, wherein the chisel composition includes a polymer having one or more binding points with a high affinity for the surface, and one or more hydrophilic segments that form a hydrophilic coating on the surface, rendering the surface water-wet and thereby facilitating the removal of oil from the surface. The invention also provides for methods of use of such formulations.

RELATED APPLICATIONS

This application claims the benefit of U.S. Provisional Application Ser.No. 61/333,085 filed May 10, 2010 and U.S. Provisional Application Ser.No. 61/379,783 filed Sep. 3, 2010. The entire contents of theabove-referenced applications are incorporated by reference herein.

FIELD OF THE APPLICATION

The application relates generally to removing hydrocarbons from surfacesand preventing hydrocarbons from adhering to surfaces, e.g., in oil andgas reservoirs.

BACKGROUND

A considerable portion of the world's hydrocarbon endowment exists incarbonate geological formations, while other oil-bearing and natural gasreservoirs are found in sandstones, coalbeds, salt layers, or shales. Asthese oil and gas reservoirs mature during production, it becomesincreasingly difficult to recover the residual hydrocarbons that theystill contain. The recovery of hydrocarbons from mature reservoirs tendsto be low for two reasons: the reservoirs have low porosity, and thereservoir rock is oil-wet. The combination of these factors means thatwhen oil and gas flow towards the wellbore for production to thesurface, there is diminished flow of the oil and gas. The oil-wet andreduced porosity conditions also reduce productivity when enhanced oilrecovery (EOR) techniques are employed, such that the injected EORfluids will bypass the oil that resides in the rock matrix. This problemis not limited to mature reservoirs. During conventional, primary orsecondary production of hydrocarbon fluids, the reduced porosity and oilwet conditions reduce the productivity of the well. For example,formation damage occurs by deposition of asphaltenes, condensates, andwaxes. The prevention of this type of deposit would avoid the loss ofproductivity.

The oil-wet state of the reservoir can be caused by asphaltenedeposition. Asphaltenes, naturally-occurring components of crude oil,are a complex mixture of aromatic structures that have carboxylfunctional groups, characterized, for example, by being insoluble inheptane. Their low solubility leads to their precipitation anddeposition onto rock surfaces, causing an oil-wet condition. Thepermeability of the pores in the carbonate formation is thus reduced asthe asphaltene on the surface rock plugs the pore throats. In additionto asphaltenes, gas condensates and waxes form during production,creating an oil-wet condition on the surfaces and in the pores of thepetroleum-bearing geologic formation. Gas condensates are liquid or waxyorganic materials that deposit in the near-wellbore region, includingthe fractured zones and proppant packs, of gas producing wells. Waxesare heavy oil fractions or paraffinic materials that can adhere tosurfaces.

Removing asphaltenes, condensates, and waxes from oil-containingformations remains an important challenge for oil and gas recoveryoperations, especially for mature wells where enhanced oil recoverytechniques are to be employed. Current approaches to this probleminclude: (1) dissolving the asphaltenes by treatment with aromaticsolvents such as xylene or toluene, or by treatment with dendrimericpolymers; (2) injecting chemicals into the formation to preventasphaltene deposition; and (3) altering the wettability of theformation. The first two technologies provide only temporary solutions,because they do not slow down the ongoing process of asphaltenedeposition. These technologies are also expensive, and incomplete intheir ability to treat the entire formation at one time. By changing thewettability of the formation from oil-wet to water-wet, it may bepossible to effect a more durable change. Treatment fluids for changingthe wettability have been proposed that include, e.g., lignosulfates(see U.S. Pat. No. 6,051,535) or nanoparticles (see U.S. Pat. No.4,579,572). However, conditions in the reservoir are harsh andinhospitable to chemical manipulations. Moreover, permeability andporosity of the well should be preserved or enhanced with any proposedtreatment. Therefore, there remains a need in the art for well treatmentmethods that can enhance the recovery of oil from existing oilreservoirs, while avoiding deleterious effects on the recoveryefficiency of the formation.

Oil recovery can also be enhanced by treating the wellbore itself, bytreating the formation in workover operations, or by treating theformation as fracturing fluid (“frac fluid”) is installed. The wall ofthe wellbore can become clogged with fluids that have contacted it, suchas asphaltenes, waxes and other hydrocarbon materials from the well, andwellbore oil that has been used during drilling processes. The formationmatrix, especially the near wellbore area of the formation, can alsobecome clogged with such deposits. Paraffin deposits can form because ofa decrease in temperature below the wax appearance temperature of theoil. Asphaltene deposits can form because of agglomeration, oxidation orchemical interaction of maltene content with incompatible fluids, orpressure or temperature changes. Such deposits can develop in thewellbore and in the formation throughout the lifecycle of the well.Treatments for these organic deposits have included various aromaticsolvents and surfactants, as well as high intensity acoustic sources,injection of deasphalted oil, cleaning with carbon dioxide, use ofmicroorganisms, etc.

Acids have been used for oil well treatments aimed at improvingproductivity. For example acid fracturing is a commonly used techniquefor increasing the production of oil from a carbonate geologicalformation. During the acid fracturing treatment a fluid is introduced atsufficient pressure to form fractures in the formation. Acid is theninjected into the fracture to chemically react and etch the face of thefracture. The result is that channels are created and the productivityof the well is increased.

Acids are also used in acid treatment aiming at restoring formationdamages. In this case the acid is used in areas near the wellbore toreverse the formation damage and restore well productivity. Anotherapplication of acids is to reverse the wettability of the formation fromoil to water wet. This is particularly relevant in carbonate formationswhere the asphaltenes tend to deposit on the carbonate surface forming astrong interaction. The oil wet state results in a low success inenhanced oil recovery technique because the injected fluids tend tobypass the oil. Acid has shown to be useful in these situations wherethe chemical reaction between acid and carbonate help to detach the oilfrom the rock. Currently several acids are used for these applicationsincluding: mineral acids (hydrochloric acid, hydrofluoric acid, or theirmixtures); organic acids (acetic acid, formic acid, chloroacetic acid,sulfamic acid, etc.). However these acids tend to be precipitated orconsumed relatively quickly and near the wellbore, losing their abilityto react deep into the formation or treat surfaces for extended periodsof time. One solution is to protect the acid in such a way that it willnot be rapidly precipitated or consumed near the wellbore.

There remains a need in the art, therefore, for technologies to improvethe cleanout of near wellbore oily deposits to enhance flow of oil intothe wellbore. In addition, for reservoirs where hydraulic fracturing isemployed, it is desirable to prevent the buildup of hydrophobic residuaon the rock surfaces and on the proppant materials. Preventing theaccumulation of such residua can improve the efficiency of the hydraulicfracturing endeavor and can improve well productivity.

SUMMARY

1. Formulations

Disclosed herein, in embodiments, are formulations for facilitating theremoval of oil from a surface, comprising a chisel composition, whereinthe chisel composition comprises a polymer having one or more bindingpoints with a high affinity for the surface, and one or more hydrophilicsegments that form a hydrophilic coating on the surface, rendering thesurface water-wet and thereby facilitating the removal of oil from thesurface. In embodiments, the surface can comprise carbonate rock ormetal. In embodiments, the polymer comprises polyphosphoric acid (PPA),and the PPA can be protected by a protected mechanism, to form protectedPPA. In embodiments, the polymer is a functionalized polymer. Thefunctionalized polymer can be protected by the protective mechanism toform a protected polymer. In embodiments, the protective mechanism canbe selected from the group consisting of polymer encapsulation, polymerentrapment within a matrix, and polymer masking with a masking agent. Inembodiments, the polymer can be adapted for controlled release, and thecontrolled release can be actuated by a triggering mechanism. Inembodiments, the controlled release can be accomplished by a mechanismselected from the group consisting of dissolution, diffusion, pH change,ionic strength change and temperature change. In embodiments, thefunctionalized polymer can be end-functionalized, or functionalizedalong a polymer backbone. In embodiments, the binding points have highaffinity for CaCO₃ or for silica. In embodiments, the formulation canalso comprise a surfactant.

In other embodiments, a molecular chisel formation is disclosed as setforth above in the preceding paragraph, in combination with a protectivemechanism. In embodiments, the chisel composition in this formulationcomprises PPA. In embodiments, the protective mechanism can be acontrolled release mechanism. In embodiments, the protective mechanismcan delay the hydrolysis of the PPA.

2. Methods

Further disclosed herein, in embodiments, are methods for reducing theattachment of oil to a surface, comprising providing the molecularchisel formulation as described in the “Formulations” paragraph above,and directing the molecular chisel formulation into contact with thesurface, thereby providing a water-wet surface that impairs theattachment of oil and reduces the attachment of oil thereto. Inembodiments, the surface is selected from the group consisting of aCaCO₃ surface, a silica surface, and a metal surface. The method canfurther comprise a step of exposing the surface to a surfactant priorto, simultaneous with, or following the step of directing. Disclosedherein, in addition, are methods for recovering oil from a formationcontaining oil retained on a rock surface, comprising providing themolecular chisel formulation as described in the preceding paragraph,directing the molecular chisel to contact the rock surface, therebyrendering the rock surface water wet and thereby impairing theattachment of oil thereto, and recovering oil from the formation afterthe attachment of the oil to the surface has been impaired by thepreceding step. Also disclosed is an oil produced by this method.

Also disclosed herein, in embodiments, are methods for mobilizing oilfrom a reservoir formation, comprising providing an oil retrievalformulation comprising a fracturing fluid and the formulation disclosedin the “Formulations” paragraph above, and fracturing the formation withthe oil retrieval formulation, thereby mobilizing the oil for retrieval.Disclosed herein, too, are retrieved oils, where such retrieved oils aremobilized by the preceding method described above. Disclosed herein, inother embodiments, are methods for preventing deposition of an oil on asurface, comprising providing the formulation disclosed in the first“Formulations” paragraph, directing the formulation into contact withthe surface, and exposing the surface to the formulation to preventdeposition of the oil thereupon. Disclosed herein, in other embodiments,are methods of facilitating the removal of oil residua from a nearwellbore region, comprising providing the formulation disclosed in thefirst “Formulations” paragraph above, and directing the formulation intocontact with the near wellbore region to impair attachment of the oilresidua thereto, thereby loosening the oil residua from the attachmentand facilitating their removal from the near wellbore region. Inembodiments, oil residua can comprise asphaltenes, paraffins or waxes.

DETAILED DESCRIPTION

1. Compositions and Formulations Generally:

In embodiments, the water-based fluids disclosed herein comprisecompositions that act as a molecular “chisel” to detach hydrocarbonsfrom surfaces in a hydrocarbon-bearing formation, and that concomitantlychange the wettability of the formation from oil-wet to water-wet. Inembodiments, the water-based fluids disclosed herein also comprise oneor more surfactants that can reduce the interfacial tension (IFT)between crude oil and water. In embodiments, solvents can be used indispersed or emulsified forms with the chisel formulations to disperse,soften or dissolve hydrocarbons.

In embodiments, the chisel compositions comprise polymers having twomain constituents. One constituent (the “binding points” of the chisel)has one or more functionalities that display high affinity for thesurface of the formation; the other constituent (the “hydrophilicsegment” of the chisel) is hydrophilic, and can form a coating on therock and/or protrude from the rock surface to make it hydrophilic. Thechisel composition, comprising the binding points and one or morehydrophilic segments, can arrange itself in the reservoir formation byattaching itself to the reservoir rock at the binding points. Thehydrophilic segment(s) will form a layer on the rock, creating awater-wet condition on its surface.

In one embodiment of a formulation for detaching hydrocarbons fromsurfaces in the formation, a chisel composition can work in synergy witha surfactant. The role of the surfactant in the formulation is to reducethe interfacial tension between the water and hydrocarbons to mobilizethe oil that is coating the rock by “pulling” it from the rock surface.This can create a meniscus around the oil allowing the chiselformulation to enter in contact with the rock. The result is a change inthe wettability of the rock, from oil to water wet. In this embodiment,the surfactant in the formulation can change the behavior of the oil onthe rock so that there is an entry point for the chisel formulationbeneath the oil itself. In embodiments, surfactants like those typicallyused in enhanced oil recovery (e.g., anionic surfactants like sulfates,sulfonates, carboxylates, phosphates, phosphonates and the like, ornonionic surfactants like alkylphenyl, alkoxylates, alkyl alkoxylates,EO/PO copolymers and the like) can be advantageously used together withthe chisel formulations to enhance the activity and the efficacy of thechisel formulation. In embodiments, the chisel compositions can be usedwithout a surfactant.

In embodiments, the chisel compositions can be used with other additivesin treating a surface, for example, in combination with an acid as acomponent of an acidizing treatment.

In embodiments, chisel formulations can optionally include chelatingagents for binding divalent cations or other chemicals in the reservoir.The water found in hydrocarbon reservoirs often contains divalentcations like Ca⁺⁺ and Mg⁺⁺. These materials could attach to the bindingpoints of the chisel, preventing the chisel from attaching effectivelyto the cationic surface of the reservoir. In order to prevent thedepletion of the chisel's binding capacity by these free ions, smallmolecules having cationic binding capacities could be added to theformulation to scavenge the divalent cations. Such materials are knownin the art as chelating agents, chelants or sequestrants. Examples ofsuch materials include citric acid, phosphoric acid, glycolic acid,tartaric acid, oxalic acid, EDTA, and the like. In embodiments, a waterpreflush can be used before the chisel treatment to displace solubleions like Ca⁺⁺ and Mg⁺⁺ from the water surrounding the rock surfaces tobe treated by the chisel, and/or to displace the connate water in orderto reduce the concentration of dissolved hardness ions in the formation.In embodiments, other treatments, such as acid treatments, can be usedin addition to or prior to the use of the chisel formulation. Inembodiments, the chisel formulations can optionally includelignosulfonates, wettability enhancers such as fluoro chemicals, and/ornanoparticles.

For use in treating hydrocarbon formations, the water-based formulationsdisclosed herein can be applied to the formation using techniques thatare consistent with techniques used in the industry. In embodiments, theformulations and methods disclosed herein can be adapted for treatingcarbonate reservoirs. For such reservoirs, the binding points of thechisel can comprise functionalities that display an affinity for CaCO₃.For example, binding point functionalities can include carboxylic acids,phosphonates, phosphates, biphosphonates, sulfonates, sulfates,chlorophenols, quinoline oxides, and the like. In other embodiments, theformulations and methods disclosed herein can be adapted for treatingsandstone reservoirs. For such reservoirs, the binding points of thechisel can comprise functionalities that display strong interactionswith silica. Examples include silanes and cationic compounds.

In embodiments, the formulations and methods disclosed herein can beadapted for the treatment of other surfaces as well, where removingasphaltene deposits and providing a water-wet state would be desirable.For example, steel surfaces in oil well drilling and storage may befouled with asphaltene so that they are oil-wet; advantageously, achisel formulation designed for cleaning such a surface would havestrong interactions with steel.

In embodiments, chisel compositions for carbonate formulations cancomprise oligomeric or polymeric structures. As used herein, the term“polymer” means the polymerization product of one or more monomers andis inclusive of homo-, co-, ter-, tetra-polymers, etc. and oligomericpolymers; “mer” or “mer unit” means that portion of a polymer derivedfrom a single reactant molecule; “copolymer” means a polymer thatincludes mer units derived from two reactants (normally monomers) and isinclusive of random, block, segmented, graft, etc., copolymers;“oligomer” is a short-chain polymer. In embodiments, these polymericstructures can be functionalized, having one or more functional groupscovalently linked thereto. In embodiments, chisel compositions caninclude structures having polymers functionalized at the end of thepolymer chain, or polymers having multiple functionalizations along thepolymer backbone.

For synthesis of polymer chains with end-functionalization, startingmaterials can include water-soluble polymers with functional groups atthe end of the polymer chains that can be chemically modified to yieldcalcium-binding (calcium chelating) functionalities. Examples ofstarting polymers with a functional group at one end include:alkoxy-PEGs (Carbowax MPEGs from Dow Chemical), and Jeffamines (M-1000,M2070 from Hunstman Chemical). Examples of starting polymers with twofunctionalization groups, one at each end include: polyethylene glycols(PEGs) (Carbowax PEGs from Dow Chemical), Jeffamines (Jeffamines areED-600, ED-2003 form Hunstman Chemical), polyphosphoric acid, PEG-PPGblock copolymers (Pluronics from BASF), and PEG diglycidyl ether. Suchmaterials can be functionalized to yield a polymer having, for example,one of the following functionalities at the end of the polymer chain:phosphates, phosphonates, biphosphonates, chlorophenols, polyols,polyamines, hydrophilic segments, ethylene oxide segments, propyleneoxide segments, quinoline oxides, o-benzene dicarboxylic acid,1,2,3-benzene tricarboxylic acids, and the like.

For synthesis of polymers having multiple functionalizations along thepolymer backbone, starting materials can include polymers with one ormore functional groups along the backbone that can be chemicallymodified to result in a polymer with several calcium chelatingfunctionalities. Starting polymers used for this modification caninclude: polyvinyl alcohol, styrene maleic anhydride resins (Sartomer),Joncryl polymers (BASF), polyethyleneimine, polyacrylic acid,polymethacrylic acid, polyphosphoric acid, lignin, and the like.Functional groups on the polymer backbone can include o-benzenedicarboxylic acid, 1,2,3-benzene tricarboxylic acid, phosphates,biphosphonates, chlorophenols, quinoline oxides, and the like.

In embodiments, chisel molecules can be synthesized that have boronicacid functionality, represented by the following chemical structure:

R—B(OH)₂

where R is selected from the group consisting of a polymer, wherein theboronic acid group is bonded directly or indirectly to the polymerbackbone, or is a moiety for directly or indirectly functionalizingpolymeric chains as described as R—B(OH)₂.

Boronic acid functionality can provide chelant properties, and has theadditional benefit of stability at high temperatures, making its useappropriate for reservoirs with high bottom hole temperature. Inembodiments, a boronic acid functionality can be introduced in apolyethylene glycol chain by coupling a poly(ethylene glycol)monocarboxymethylether, monomethyl ether polymer with3-aminophenylboronic acid, using carbodiimide as the coupling agent.Another set of functional groups having properties similar to boronicacid and that can be used according to the instant invention are themonoesters of boric acid. Chisels containing such functional groups canbe used in reservoirs with lower bottom hole temperatures, for example,below 60° C.

In other embodiments, phosphonic acid functionality can be added to thechisel formulation. This can add stability in the presence of highbottom hole temperatures. This functional group can be added to a chiselcomposition by coupling a poly(ethylene glycol) monocarboxymethylether,monoethyl ether polymer with 3-aminopropyl phosphonic acid usingcarbodiimide as the coupling agent. In another embodiment, thephosphonic acid functionality can be added to a polyethylene glycol byreacting a PEG-based Jeffamine with dimethyl(carboxymethyl)phosphonateusing dicyclohexylcarbodiimide as the coupling agent, then treating theproduct with HBr-acetic acid to yield the free phosphonic acid group.

In other embodiments, amidophosphoric acid functionality can be added,again yielding chisel formulations that are likely to be relativelystable at high temperatures. This group may be introduced by reacting awater soluble Jeffamine with diethylchlorophosphate to form theamidophosphate, then hydrolyzing the product to yield theamidophosphoric acid.

In other embodiments, catechol functionality can be added to the chiselformulation. It is understood that catecholic hydroxyl groups displaystronger acidic properties than many other hydroxyl groups, so that theyare good chelants to metal oxides, especially when they are in adeprotonated form. Catechol derivatives of polyethylene glycols can beadvantageously used for synthesizing chisel formulations.

2. Polyphosphoric Acid Chisel Compositions and Methods

Disclosed herein, in embodiments, are methods for improving oil recoveryby treating the oil-bearing formation with a chisel compositioncomprising polyphosphoric acid oligomers or polymers (collectively,“PPA”). In embodiments, these methods can be extended to PPA-containingcompositions in aqueous solutions (for example, for enhanced oilrecovery, acid fracturing, and the like) or in organic solutions likediesel oil, mineral oil, xylene, toluene, and the like (e.g., forrecovering damaged wellbores by cleaning the wellbore).

In embodiments, the polymeric or oligomeric form of PPA can be protectedwith a protective mechanism to prolong its effectiveness to increase theproduction of hydrocarbons from a formation. As an example, a protectivemechanism can include a mechanism like encapsulating the PPA, trappingthe PPA in a matrix, masking the PPA with a masking agent, and the like.The aim of the protective mechanism is to protect the PPA fromenvironmental conditions up to the time when the acid is needed. A PPAthat has been protected with a protective mechanism can be called“protected PPA.” Methods for oil recovery utilizing PPA include, inembodiments, methods for delaying the hydrolysis of PPA in aqueousenvironments, and methods for effecting the controlled release of PPA byvarious triggering mechanisms. The method for delaying the hydrolysis ofPPA in aqueous environments can include encapsulation/trapping of PPA ina polymer matrix, protecting the acid groups of the PPA with compoundssuch as urea or polycationic compounds, and/or protecting the PPA byemulsification with surfactants (each of these mechanisms exemplifying a“protective mechanism” that forms protected PPA). The controlled releaseof PPA by various triggering mechanisms can be used, for example, for aPPA-containing composition that is stable under one condition and istriggered to release the PPA by a change in that condition. Theconditions whose changes trigger the release of PPA can includetemperature, dissolution, pH, etc. The controlled release process can beused for applications such as recovering oil from a formation, restoringa damaged formation by changing the wettability of its surface, and thelike.

In embodiments, the water-based formulations disclosed herein cancomprise PPA or protected-PPA containing compositions that act as a“chisel” to detach hydrocarbons from surfaces in the formation, and thatconcomitantly changes the wettability of the formation from oil-wet towater-wet. In embodiments, the water-based formulations disclosed hereincan also comprise one or more surfactants that can reduce theinterfacial tension (IFT) between crude oil and water. In embodiments,solvents can be used with the chisel formulations to disperse, soften ordissolve hydrocarbons.

Without being bound by theory, the PPA (i.e., the polyphosphoric acidpolymers or oligomers) can act as a strong acid and can have highaffinity for the surface of the formation due to its plurality ofphosphate groups: the multiple anionic groups can allow the PPA to bindto the rock via multiple points, making the rock hydrophilic due to thepresence of free ionic groups and presence of multiple P═O polar groups.The result is a water-wet condition on the surface of the formation. PPAis an advantageous chisel material because it has dual properties as anacid and polymer. For the compositions and methods disclosed herein, PPAcan be an oligomer of orthophosphoric acid, but having higher aciditythan orthophosphoric acid. Its acidity increases as the number ofpolyphosphoric acid units increase in the PPA polymer due to the abilityof the longer chain PPA to stabilize multiple negative charges byresonance.

In embodiments the PPA can be used in an acid fracturing compositionwhere the polyphosphoric acid is released slowly, for example bycontrolled release, allowing for the acid to treat sections of theformation further away from the wellbore. In embodiments, the controlledrelease mechanism is actuated by a trigger mechanism such as a change inthe temperature of the formation deeper underground, the addition of pHmodifiers to the formulation, the diffusion of the fluid of theformation into protected PPA, the dissolution of the protectivemechanism of the protected PPA so that the PPA can diffuse into thefluid of the formation, and the like.

In embodiments, PPA, as used for the compositions, formulations andmethods described herein, has a degree of polymerization from about 2 toabout 20 phosphorous repeating units arranged in a linear, branched, orcyclized structure. In embodiments, the PPA is employed in the acidicform. In embodiments, the PPA is a neutralized anionic salt form, withcounterions such as alkali metals, ammonium ion, ammonium salts,alkanolammonium salts, and the like. In embodiments, the PPA basedchisel formulation further comprises chelating agents, acids,surfactants, and/or solvents. In embodiments, the PPA chisel formulationcan be delivered as a controlled release form, wherein the PPA and anyother agents within the formulation are released in a controlled manner.

As described below, it has been demonstrated that PPA can etch acarbonate rock and adsorb onto the rock, providing a more hydrophilicsurface and resulting in a change of its wettability from oil-wet towater-wet. This phenomenon does not take place, though, when a carbonaterock is exposed to monomeric phosphoric acid, demonstrating thedifference between PPA and the simple phosphoric acid monomer. PPA losescertain of these advantageous properties when dissolved in water,because it hydrolyzes to monomeric orthophosphoric acid.

In embodiments, the PPA can be protected with a protective mechanism sothat it maintains these useful properties. For example, PPA can beencapsulated so that its functionalities are protected, allowing it toact more efficiently as a molecular chisel to remove oil from surfacesand improve oil and gas recovery from subterranean reservoirs. Commonlyused encapsulating techniques can compromise the stability of the PPA,however, and encapsulation can be difficult to accomplish due to avariety of factors, including the relatively fast hydrolysis of the acidin protic solvent, low or negligible solubility in non-protic solventsand, high viscosity. Disclosed herein in embodiments are methods forencapsulating PPA to protect it against hydrolysis and consumption nearits injection point.

In embodiments, PPA can be protected by entrapping, embedding orotherwise encapsulating it in a polymeric matrix. For example, PPAcomposites can be formed comprising a core-shell structure in which thePPA is in the core, and the shell is an encapsulating polymer. Inembodiments, the PPA can be encapsulated within or commingled with apolymeric matrix. The polymeric matrix can be selected to allow for acontrolled release of the PPA, with the matrix being selected accordingto the salient characteristics of the wellbore (its temperature, thedistance that the acid needs to penetrate into the formation, thepresence and nature of carrier fluid (e.g., drilling fluid, completionfluid, formation water) and the like).

As an example, encapsulated PPA compositions can be formed as follows.Minimum amounts of a volatile solvent are added to the PPA to yieldsolutions concentrated in PPA but with lower viscosity than pure PPA.The solvent is selected so that it does not hydrolyze the PPA to asignificant degree. This PPA solution is then added to a solution ofencapsulating polymer in an organic solvent. In embodiments, the PPAsolution can be formed to be miscible with the encapsulating polymersolution; in other embodiments, the PPA solution can be suspended oremulsified in the polymer solution. The solution or emulsion containingthe combination of PPA and encapsulating polymer can then be manipulatedto yield encapsulated PPA. For example, spray drying of the mixture canyield the encapsulated PPA. Or, for example, encapsulated PPA compositecan be obtained by precipitating the polymer-PPA mixture by combiningthis mixture with another agent that acts as a non-solvent for thepolymer. As another example, encapsulated PPA composites can be formedusing a dry process. In embodiments, the encapsulating polymer can be awax, or oil, an olefin co-polymer, a fatty acids, or the like, or blendsthereof. Using wax, for example, the encapsulating wax melts and mixeswith the PPA under high shear conditions to form a uniform mixture thatcan then be broken down into small particles. In embodiments,encapsulating methods can be used that are analogous to those employedin the pharmaceutical industry, with modifications as needed to avoidthe long contact of PPA with protic solvents.

In embodiments, an encapsulated or otherwise protected PPA can beproduced that is responsive to various triggering mechanisms that caneffect a controlled release of the PPA from its protected state.Desirably, a triggering mechanism can be selected, whereby a change in acondition permits the release of the PPA from its protective mechanism.In embodiments, encapsulation materials or matrix materials can beselected that permit the controlled release of PPA from its protectedstate when a specific triggering mechanism or condition is encountered(e.g., temperature, time, pressure, pH). Protective mechanisms can beselected so that the protected PPA relying upon the specific protectivemechanism is responsive to a predetermined triggering mechanism, therebyallowing the PPA to be released in a controlled manner. As an example,dissolution of a matrix or of an encapsulation can be engineered toallow the controlled release of PPA. Using this mechanism, PPA that isentrapped/encapsulated in a matrix can be released in a controlledmanner as the matrix slowly dissolves over time. With this mechanism,the controlled release of PPA can be adjusted by controlling thedissolution rate of the matrix. Examples of encapsulants for entrappingPPA and permitting its controlled release in aqueous media include:polyethylene glycol, polyvinyl alcohol, polyvinyl pyrrolidone and itscopolymers, and the like. Examples of encapsulants for entrapping PPAand permitting its controlled release in organic media include: wax, oilsuch as palm oil, hydrophobic polymers, co-polymers, and the like.

As another mechanism for the controlled release of PPA, diffusion can beemployed. Using this mechanism, the PPA can be encapsulated in amaterial like a glassy hydrogel that can slowly swell in the waterphase, permitting the controlled release of the PPA. Examples ofmaterials suitable for use with this mechanism include hydrophilic gums(guar gum), xanthan gum, hydroxypropyl methylcellulose (HPMC), carboxymethyl cellulose (CMC), polyacrylamides, ammonioalkyl methacrylatecopolymers such as the Eudragil RL, RS series available from Evonik, andthe like.

As another mechanism for the controlled release of PPA, the pH can bechanged. Using this mechanism, the selected encapsulation material canbe responsive to changes in pH so that it that allows the PPA to bereleased in a controlled manner under certain pH conditions. Examples ofsuitable encapsulation materials include ionic coating polymers thatbecome more soluble in a solvent upon changing the pH, thereby allowingthe PPA to be released. Examples of coating polymers that respond tochanges in pH in this way are the Eudragit L, S FS, E series by Evonic,cellulose acetophthalate, Shellac, and the like.

As another mechanism for the controlled release of PPA, the temperatureof an encapsulation material surrounding the PPA or a matrix materialsupporting the PPA can be changed, allowing the PPA to be released in acontrolled manner. Examples of suitable materials that respond totemperature in this way are glycerides (totally or partiallyacetylated), Witepol, Imwitor family by Sasol, wax or other hydrophobicpolymers that has the appropriate melting temperature. These materialscan melt at certain selected temperature, for example, releasing thePPA.

Another mechanism for protecting PPA and allowing for its release on acontrolled basis involves masking PPA with a masking agent and thenunmasking it. The masking agent acts as a protective mechanism toprotect the PPA. In embodiments, for example, the PPA can be protectedby adding ionic groups that mask the PPA groups. These protecting groupshinder or delay the hydrolysis of the PPA. Materials for masking agentscan include urea, polycations, and the like. The polycations can beselected for their hydrophilicity and cationic charges. In embodiments,the polymers can be naturally derived, for example, proteins andglucosamines. Polymers used for these purposes can be applied as coatingpolymers. For preparing protected PPA in this manner, PPA and theprotective material (e.g., the masking agent, such as a cationicsubstance) can be first placed in an aqueous solution, with subsequentaddition of a water-miscible and non-solvent for the cationic polymer.In other embodiments, protected PPA can be prepared with a masking agentby placing the PPA and the masking agent (e.g., the cationic substance)in an aqueous solution and increasing the pH to precipitate the maskingagent. Examples of polycations suitable for use as masking agentsinclude SMAi (imidized styrene maleic anhydride), zein, casein, or anyof a number of polyamines (such as polyvinylamine, polyallylamine,polyethyleneimine) and their derivatives (such as PEGylated varieties),poly-DADMAC, chitosan, and cationic proteins or glycoproteins. Inembodiments the masking agents can have a switchable solubility profile,as a function, for example, of pH, temperature or ionic strength, tofacility the release of the PPA. In such an embodiment, the change inpH, temperature, ionic strength or the like functions as a triggeringmechanism to actuate the controlled release of the PPA.

Another type of PPA masking involves the use of emulsification of PPA incombination with a surfactant. According to this mechanism, PPA is mixedwith a solution containing a surfactant, which is then added to ahydrophobic solvent to form an emulsion of the PPA in the organicsolvent. The shielding of the PPA by the emulsifier layer delays theconsumption and/or hydrolysis of the PPA. In an embodiment, thesurfactant is cationic and forms strong ion pair compounds with the PPA.Upon mixing the surfactant with the PPA in a common solvent, the ionpair is formed. Then addition of the complex to a hydrophobic solventresults in the lipophilic portion of the surfactant extending into thehydrophobic solvent phase and stabilizing the PPA-containing droplets.Non-limiting examples of these surfactants are: Decyl trimethyl ammoniumbromide, Dodecyl trimethyl ammonium bromide, Dodecyl triphenylphosphonium bromide, Arquad C-50, Arquad T-50, benzethonium chloride,benzalkonium chloride, Adogen 464.

In other embodiments, the surfactant can be a non-ionic with a low HLBvalue. Similar to the above case, when the surfactant and the PPA aremixed in a common solvent, the hydrophilic portion of the surfactantinteracts with the PPA, which is hydrophilic. Then addition of thecomplex to a hydrophobic solvent results in the lipophilic portion ofthe surfactant extending into the hydrophobic solvent phase andstabilizing the PPA-containing droplets. Examples of these surfactantsare: sorbitan monooleate (Span 80), sorbitan monostearate (Span 60),nonyl phenol ethoxylated such as CO-210 from Rhodia, octylphenolethoxylated such as Triton X-15 form Dow, etc. The PPA protected by thismethod is in the form of a water in oil emulsion, and the PPA can bereleased into an aqueous system when needed by adding to the emulsion asolution containing hydrophilic surfactant that breaks the water in oil(W/O) emulsion.

3. Exemplary Applications for Molecular Chisel Technology

In embodiments, the formulations disclosed herein can be used forincreasing oil and gas recovery from a reservoir. In embodiments, suchformulations can be used for increasing oil recovery from a maturereservoir in a carbonate formation. For mature reservoirs, the recoveryof oil by injecting aqueous fluids (i.e., enhanced oil recovery or EOR)is typically inefficient, in part because the injection fluid cannotpenetrate the pores of the formation due to their oil-wet conditions.The formulations and methods disclosed herein offer approaches toimproving oil recovery efficiency by removing asphaltene deposits andchanging the oil-wet state of the oil-bearing rock to a water-wet state.

In other embodiments, the formulations disclosed herein can be used forremoving oily deposits from near-wellbore reservoirs and preventing orremediating near wellbore damage. It is understood in the art that thetrajectory of a near-wellbore reservoir is complex and tortuous. Ledgesand cavities exist in these regions that tend to collect fluid that hascontacted them. Fluids so collected can include wellbore oil,asphaltenes, waxes and other hydrocarbon materials from the well. Thesematerials adhere to the surfaces of the passages within the nearwellbore region and can plug the pores in the wellbore. Thesecollections clog the passages, preventing oil flow and producingwellbore damage. Use of the formulations disclosed herein can becombined with other components of a treatment mixture that can releaseunwanted hydrocarbon-based clogging materials from the rock surface inthe near wellbore region. The chemical functionality of theseformulations can interact strongly with the rock surface, resulting in arelease of materials bound thereto, and ultimately enhancing the flow ofoil. Due to the hydrophilic nature of these formulations, a water-wetcondition will be produced on the rock surface, which can prevent thesubsequent build-up of oil, waxes, asphaltenes and other oleophilicmaterials.

In yet other embodiments, the formulations disclosed herein can be usedas part of a frac fluid treatment system. These formulations, which aresoluble or dispersible in the frac fluid, can be carried by the flow ofthe frac fluid into the reservoir, where they can perform threedesirable processes: 1) introducing cracks in the reservoir tofacilitate the flow of oil, 2) releasing oil from rock surfaces, and 3)coating the surface of the formation rock with a composition that leavesthe formation in a water-wet state that can prevent subsequentdeposition of asphaltenes thereupon. In embodiments, these threeprocesses can take place approximately simultaneously.

In embodiments, formulations and methods are disclosed herein forincreasing oil recovery from a reservoir, particularly a maturereservoir in a carbonate formation. For mature reservoirs, the recoveryof oil by injecting aqueous fluids (i.e., enhanced oil recovery or EOR)is typically inefficient, in part because the injection fluid cannotpenetrate the pores of the formation due to their oil-wet conditions.The formulations and methods disclosed herein offer approaches toimproving oil recovery efficiency by removing asphaltene deposits andchanging the oil-wet state of the oil-bearing rock to a water-wet state.

One method for detaching hydrocarbons from surfaces in the formationusing the disclosed formulations involves synergistically employing achisel composition with a surfactant. The role of the surfactant is toreduce the interfacial tension between the water and hydrocarbons tomobilize the oil that is coating the rock by “pulling” it from the rocksurface. This creates a meniscus around the oil allowing the chiselformulation to enter in contact with the rock, changing its wettabilityfrom oil-wet to water-wet. In this method, the surfactant formulationchanges the behavior of the oil on the rock so that there is an entrypoint for the chisel formulation beneath the oil itself. In embodiments,surfactants like those typically used in enhanced oil recovery (e.g.,anionic surfactants like sulfates, sulfonates and the like, or nonionicsurfactants like alkylphenyl, alkoxylates, alkyl alkoxylates, and thelike) can be advantageously used together with the chisel formulationsto enhance the activity and the efficacy of the chisel formulation. Inembodiments, tunable or switchable surfactants can be used together withthe chisel formulations.

In embodiments, the formulations, compositions and methods disclosedherein can provide for enhanced oil recovery from undergroundreservoirs, resulting in increased oil production and/or decreased watercut. In embodiments, the formulations, compositions and methodsdisclosed herein can provide for reservoir stimulation, for example fornew well completions, workover of existing wells, as adjunct toacidizing methods, and the like In embodiments, the formulations,compositions and methods disclosed herein can provide for repair of nearwellbore damage, for example by removing oil residua such as asphaltenesand/or paraffins and/or waxes, or by improving permeability in the nearwellbore region, resulting in improved flow of oil, water, natural gasand condensates. Other uses for the formulations, compositions andmethods can be envisioned. The chisel technologies disclosed herein canbe used alone or in combination with other technologies familiar in theoil and gas industry, including the use of surfactants (includingtunable surfactants), solvents (e.g., diesel, naphtha, mineral oil,hexane, pentane, heptane, xylene, d-limonene and the like) or emulsionsthereof, acids, chelants, polymer rheology modifiers, water shutoffchemicals, microparticles or nanoparticles, or the like. In embodiments,the chisel technologies can be used for the extraction of oil, heavy oilor bitumen from mineral deposits, as is seen for example in oil sandsextraction, whether by mining processes or by in-situ thermal or steamprocesses. In embodiments, the chisel technologies can be used for thecleaning of metal surfaces, as are found in oil and gas productionequipment, pipes, transport lines and the like.

EXAMPLES

Materials: All the materials were obtained from Aldrich unless otherwisespecified.

Polyphosphoric acid, PPA, (Aldrich, product number 208213) was 115%,expressed as H3PO4 equivalent.

The “oil-wet CaCO₃ particles” described below consisted of Calciumcarbonate particles (VICAL® 1000 A-9-296-11) from Specialty MineralsInc. (Adams, Mass.) that were soaked with heavy oil (API 12°) and agedin an oven at 70° C. for 1 day.

Example 1 Synthesis of Polyethylene Glycol Phosphate

A 50 ml round bottom flask was charged with polyethylene glycolmonomethyl ether, Mn˜550 (11 g, 0.02 mol) and Polyphosphoric acid, 115%H₃PO₄ equivalent (1.7 g, 0.02 mol). The mixture was stirred undernitrogen at 100° C. for 2 hours. The product was used without furtherpurification.

Example 2 Synthesis of Polyvinyl Alcohol Modified with Phosphoric Acid

To a round bottom flask attached to a condenser, 10 ml. of phosphoricacid (35%, Aldrich) was added and heated to 110° C. Following this, 8 gof urea (Aldrich) and 2 g of Polyvinyl alcohol (88% hydrolyzed, 160,000molecular weight, Aldrich) was added to the phosphoric acid solutionwhile stirring. The reaction was continued for 2 hours at 110° C. Then80 ml of DI-water was added while stirring the mixture vigorously. Theproduct was purified by precipitating over approximately 350 ml.acetone. The precipitated solid was recovered by filtration and dried inthe vacuum oven at 75° C. until constant weight was attained.

Example 3 Synthesis of Lignin Modified with Phosphoric Acid

9.6 gm of water, 1.75 ml. of phosphoric acid (35%, Aldrich) and 7.4 gmurea were mixed in a beaker and stirred with a magnetic bar while thetemperature was increased to 80° C. Next, 2 gm of lignin (MeadWestvaco,Virginia) was added and the mixture was stirred further for 30 min. Thesolids were recovered from the mixture by filtration and heated in anoven for 150° C. for 1 hour.

Example 4 Treatment of Oil-Soaked Calcite (CaCO₃

A series of experiments was performed to evaluate the ability of variousaqueous formulations to remove a coating of aged crude oil from acalcite (CaCO₃) crystal. A heavy crude oil (API 12°, Viscosity 7,000 cpsat 25° C.) was used for the experiments, having a relatively highviscosity and low API, so that it simulated a typical hydrocarbon foundin a mature reservoir. Calcite crystals (Iceland Spar from WARD'SNatural Science, Rochester, N.Y.) were soaked for 2 days at 80° C. inthis heavy crude oil. After the 2 days, the calcite crystals wereremoved from the crude oil and the excess oil allowed to drain off.Subsequently, the oil-soaked crystals were placed into a 20 ml vialcontaining approximately 10 g of the aqueous test solutions, thecomposition of which is set forth in Table 1. The chisels in each of thetest solutions were synthesized according to the procedures described inthe previous examples, as indicated in the tables below. In all thesolutions, the pH was adjusted to pH7.

TABLE 1 Test Solutions % Surfactant Chisel Triton X-114 Experiment #Description (Aldrich) % Chisel % DI Water 4.1 — 0 0 100 4.2 — 0.5 0 99.54.3 Example 1 0.5 0.5 99.0 4.4 Example 2 0.5 0.5 99.0 4.5 Polyacrylicacid 0.5 0.5 99.0 (Mn~450,000) From Aldrich

The samples were allowed to soak and their appearance was monitored overtime.

Table 2 displays the estimated percentage of remaining oil on thecalcite crystal samples over time. The numbers were estimated from thearea of the calcite that remains coated with the oil vs. the area thatis clean.

TABLE 2 Percentage of oil on calcite samples at different timesExperiment # 2 hours 5 hours 24 hours 4.1 100 98 95 4.2 100 100 98 4.350 25 1 4.4 50 20 1 4.5 90 80 5

These experiments also estimated the contact angle of oil drops on thesurface of the treated crystals once the majority of the oil had beenremoved by the treating solutions. For samples 3, 4 and 5, the estimatedcontact angle is very high) (>135° indicating that the oil does not wetthe calcite surface, in other words, that the calcite surface iswater-wet. For samples 1 and 2 the contact angle is small) (<5°,indicating that the oil is spreading over the surface of the crystal,consistent with an oil-wet surface.

Example 5 Removal of Crude Oil from Calcite Using Chisel and Surfactant

The protocol set forth in Example 4 was employed to show that smallconcentrations of the chisel formulation in conjunction with asurfactant are able to remove aged crude oil that coats a calcitecrystal. For each of the tests listed in Table 3, the chisel formulationwas the one described in Example 1.

TABLE 3 Test solutions % Surfactant Triton X-114 % Chisel Experiment #(Aldrich) (Example 1) % DI Water 5.1 0.5 0.5 99.00 5.2 0.5 0.25 99.255.3 0.5 0.1 99.40 5.4 0.5 0.01 99.49

Table 4 displays the estimated percentage of remaining oil on thecalcite samples over time. The numbers were estimated from the area ofthe calcite that remains coated with the oil vs. the area that is clean.

TABLE 4 Percentage of oil on calcite samples at different timesExperiment # 2 hours 5 hours 24 hours 7 days 5.1 50 25 1 1 5.2 80 60 8 15.3 100 100 10 3 5.4 100 100 30 3

Example 6 Removal of Crude Oil from Rough-Surfaced Calcium CarbonateRock

The protocol set forth in Example 4 was used to evaluate the ability ofvarious aqueous formulations to remove oil from a porous calciumcarbonate rock with a rough surface. Table 5 lists the aqueous solutionsthat were used in this Example.

TABLE 5 Test solutions % Surfactant Chisel Triton X-114 Experiment #Description (Aldrich) % Chisel % DI Water 6.1 — 0 0 100 6.2 — 0.5 0 99.56.3 Example 1 0.5 0.5 99.0 6.4 Example 2 0.5 0.5 99.0 6.5 Polyacrylicacid 0.5 0.5 99.0 (Mn~450,000) From Aldrich 6.6 Example 3 0.5 0.5 99.0

Table 6 displays the estimated percentage of remaining oil on thecalcite samples over time. The numbers were estimated from the area ofthe calcite that remains coated with the oil vs. the area that is clean.

TABLE 6 Percentage of oil on calcite samples at different timesExperiment # 16 hours 21 hours 3 days 6.1 100 100 95 6.2 100 100 100 6.350 40 5 6.4 60 45 5 6.5 70 60 10 6.6 90 80 10

Example 7 Stability of PPA to Hydrolysis

Several titrations were carried out to evaluate the stability of PPA tohydrolysis at different temperatures and at different time periods.

A solution of 1 wt % of PPA in DI-water was prepared by dissolving 10 gof PPA in 1000 ml of DI-water. The solution was divided in 3 batches;one batch was left at room temperature, another batch was placed in therefrigerator at ˜0° C., and the last batch was placed in an oven set at50° C. Aliquots of the 3 batches (approximately 50 ml) were titrated atdifferent times with a 1 M NaOH solution. This information is used todetermine a degree of polymerization (DP) to show the size of thepolymer repeating structure. PPA hydrolyzes in water, resulting in alower DP after hydrolysis, eventually leading to ortho-phosphoric acid.Increasing temperature accelerates the hydrolysis as shown in Tables 7aand 7b.

TABLE 7a Hydrolysis of PPA at different conditions Temperature DP after20 Experiment # (C.) Initial DP hrs 7.1 20 4.3 3.2 7.2 50 4.3 2.0

TABLE 7b Hydrolysis of PPA at different conditions Percent Temperaturehydrolysis Experiment # (C.) after 20 hours 7.3 5 <10 7.4 20 35 7.5 50100

Example 8 Encapsulation of PPA by Spray Drying and its Performance asOil Recovery in Carbonate Formation

A solution of PLURONIC® F127 from BASF (Florham Park, N.J., USA) intetrahydrofuran was prepared by mixing 6.3 g of the PLURONIC® F127 and30 g of tetrahydrofuran. In a separate vial it was mixed 0.72 g of PPAand 1.17 g of ethyl alcohol. The solution was stirred until both liquidswere uniformity mixed. Next the PPA solution was added to the Pluronicsolution, manually shaken for a few seconds until a homogeneous emulsionwas formed and spray dried using a PREVAL Spray system. After 30 minutes1.6 g of PPA encapsulated particles were collected. Yield of the spraydrying process was ˜25%. Light microscopy was done, and encapsulatedparticles of 10-100 microns were observed. The particles were suspendedin water, and titrations were done to demonstrate that the PPA wasreleased into the solution.

Example 9 Characterization of Encapsulated PPA Particles

The spray dried polymer-encapsulated particles from Example 8 werecharacterized to evaluate the amount of PPA encapsulated in theparticles and determine the degree of hydrolysis of the encapsulatedPPA. To a beaker were added 0.092 g of the particles prepared in Example8 and approximately 10 g of DI-water. The particles were stirred via amagnetic bar and titration of the solution with a 0.01M NaOH solutioncarried out at once. The 1st equivalent point at approximately 0.07 mmolof NaOH 0.01M indicated that the particles contain approximately a 4 wt% of PPA. The 2nd equivalent point at approximately 0.12 mmol of NaOH0.01M indicates that the PPA has only been partially hydrolyzed duringthe encapsulation process leaving enough active PPA to be used infurther applications.

Example 10 Transporting Polymer-Encapsulated PPA and its ControlledRelease

This experiment shows how the encapsulated PPA can be transported to adesired location in a hydrophobic solvent and released when needed byaddition of water. A possible application of this method is wellborecleanout.

To a vial was added 0.0933 g of particles from Example 8 and 5 ml ofhexane. The mixture was shaken to form a suspension of the particles inthe hexane. The suspension was allowed to stir for 30 minutes. Afterthat period of time, visual observation of the suspension did not showany changes, suggesting the acceptability of hexane as a non-reactivetransport media. Next, 5 ml of DI-water was added to the suspension toform a two-phase mixture in which the polymer particles migrated to theaqueous phase and dissolved readily. The mixture was titrated againstNaOH 0.01 M, showing the typical 2 equivalent points of PPA. Theanalysis of the equivalent points indicates that suspending theparticles in hexane did not hydrolyze the PPA.

Example 10 Encapsulation of PPA by Spray Drying with a pH-ResponsivePolymer

A solution of poly(vinylacetate-co-crotonic acid), acid number=62-70(Aldrich, Product number 444677) was prepared by dissolving 10 g of thepolymer in 30 g of tetrahydrofuran. In a separate vial was mixed 3.5664g of PPA with 3.5 g of ethanol. The solution was stirred until bothliquids were completely mixed. Next, the PPA solution was added to thepolymer solution and manually shaken for a few seconds. The obtainedemulsion was spray dried using a PREVAL Spray system. After 30 minutes0.6 g of polymer-encapsulated PPA particles were collected.

Example 12 Controlled Release of Polymer-Encapsulated PPA by pHAdjustment

This example shows the capability of the polymer encapsulated PPA todetach oil form a calcium carbonate surface.

0.22 g of particles from Example 11 were placed in a vial containing 5ml of water and 1.5 g of “oil-wet CaCO₃ particles” (prepared asdescribed in the Materials Section). The solution was left to stand atroom temperature for a few days. Over time, the solution pH graduallyincreased, partially neutralizing the acid groups of the encapsulatingpolymer. As a result, the polymer particles became swollen, slowlyreleasing the PPA. The released PPA acted upon the surface of the CaCO₃particles, completely removing the attached oil after about four days.

Example 13 Protecting PPA with Urea

This example shows how the hydrolysis of PPA can be retarded byprotecting the acid groups with urea and, how the resulting urea-PPAcomplex maintains its oil-cleaning properties. To a beaker was added 250ml of DI-water and 3.13 g of PPA (36.7 milliequivalents of H3PO4). Tothis solution was added 2.2 g of urea (36.7 mmol) and the mixturestirred until all the urea was dissolved. The solution was kept at roomtemperature, and aliquots were titrated at different times in order toevaluate the level of PPA hydrolysis. Results were compared to a controlsample consisting of same amount of PPA in DI-water.

The results indicated that after aging for 24 hours, the control samplewas partially hydrolyzed while the PPA-urea solution remainedunhydrolyzed. After 2 days, both solutions showed partial hydrolysis ofthe PPA but in the control sample the level was higher. After 9 days thecontrol samples was fully hydrolyzed while the urea-PPA complex onlyshowed partial hydrolysis.

An experiment was also carried out to evaluate capability of urea-PPAsolution to remove oil from a carbonate surface. To a vial was added 5ml of the PPA-urea solution and 1.5 g of “oil-wet CaCO₃ particles”. Thesolution was left at room temperature for a few days and the percentageof cleaned particles was estimated over time. The results indicated thatafter 4 days approximately 60% of the particles were cleaned from theoil layer. This finding is consistent with the cleaning efficiency of acontrol PPA solution, indicating that the presence of urea does nothinder the cleaning efficiency of PPA.

Example 14 PPA Encapsulation with Wax

10 gm of paraffin wax (Aldrich, m.p. 53-57° C.) can be dissolved in 90 gof hexane.

A solution of 1 g of PPA in 2 g of ethanol can be added to the waxsolution and the whole mixture can be immediately precipitated by addingdropwise to a 500 ml of methanol. The wax-encapsulated PPA can berecovered by vacuum filtration and dried in a vacuum oven at roomtemperature for 4 hours.

Example 15 Wax-Encapsulated PPA Release by Increase in Temperature

To demonstrate the release of PPA by temperature, the encapsulated PPAprepared according to Example 14 can be suspended in water and heatedslowly. The release of PPA is monitored by measuring the pH of thesolution. At the melting temperature for the wax coating, the PPA wouldbe released into the water.

A parallel experiment can be carried out with the same parameters butwith “oil-wet CaCO₃ particles” also immersed into the solution. Theresult would be that the oil is completely removed from the CaCO3particle surface due to its interaction with the released PPA.

Example 16 PPA Encapsulation with Chitosan

A 0.1% solution can be made by dissolving Chitosan in acidic water. PPA,10 wt % based on the amount of chitosan, can be added to the chitosansolution with stirring; immediately afterwards, the pH of the solutionis increased while stirring to enable the chitosan to precipitate uponthe surface of the PPA, trapping the PPA. The solution is drained andthe substrate dried overnight under vacuum at 40° C.

Example 17 PPA Encapsulation with Wax

10 gm of wax (Aldrich, m.p. 55° C.) and 1 g of PPA (Aldrich, 115%equivalent phosphoric acid) was placed in a plastic container. Thecontainer was then loaded into a high shear mixer such as the FlackTekDAC 150 FVZ-K (FlackTek, Landrum, S.C.). The mixture was shear mixed at˜2000 rpm for 10 minutes. The high shear melted the wax and formed auniform mixture with the PPA. The mixture was then broken into smallparticles by using a blender.

Example 18 Spontaneous Imbibition Test

Spontaneous imbibition test was performed in standard Amott cells. Thetested core samples were limestone from Texas (Edwards Plateau), with aporosity 29%, and a permeability 90-110 mD. The cores were approximately1 inch in diameter and 1.5 inch in length. The cores were immersed inheavy oil (API 12°) under vacuum to fully fill all the pores. The soakedsamples was aged in an oven at 80° C. overnight. Next the oil-soakedcores were placed in a vertical position in an Amott cell and the cellfilled with about 50 ml of the test solution. The cells were placed inan oven set at 50° C., and the amount of recovered oil over time wasmonitored. Three solutions were tested: Solution A: water solutioncontaining 1 wt % of chisel material prepared in Example 1, 3 wt % NaCland 1 wt % Tergitol 15-S-40; Solution B: water solution containing 1 wt% diethylenetriamine penta(methylene phosphonic acid), 3 wt % NaCl and 1wt % Tergitol 15-S-40; Solution C: water solution containing 1 wt %commercial surfactant (branched alkyl propoxylated sulfate), 3 wt % NaCland 1 wt % Tergitol 15-S-4.

Solution C released no oil from the core over 70 days soak time, whileSolution B released 8% and Solution A released 51% of the total amountof oil from the core sample under static soaking conditions (i.e., withno mixing). These results demonstrate that the chisel compositions havethe ability to displace significant amounts of oil from the surfaces ofgeologic samples.

Example 19 Effect of PPA Hydrolysis at 20° C.

To determine the effect of PPA hydrolysis on chisel performance, asolution of 1% PPA in water was prepared and held at 20° C. for 1 day.The aged 1% PPA solution was compared with a freshly prepared 1% PPAsolution in oil removal tests. For these tests, oil coated calciumcarbonate samples were soaked in the PPA solutions for 4 days at 20° C.After soaking for 4 days, the calcium carbonate sample in the freshlyprepared PPA solution had 60% of the oil removed, while the calciumcarbonate sample in the aged PPA solution had only 30% of the oilremoved. This result demonstrates that the aged PPA may have diminishedperformance after partial hydrolysis, but that it is still able toremove from the calcium carbonate sample.

Example 20 Effect of PPA Hydrolysis at 50° C.

To determine the effect of PPA hydrolysis on chisel performance, asolution of 1% PPA in water was prepared and held at 50° C. for 1 day.The aged 1% PPA solution was compared with a freshly prepared 1% PPAsolution in oil removal tests. For these tests, oil coated calciumcarbonate samples were soaked in the PPA solutions for 1 day at 50° C.After soaking for 1 day, the calcium carbonate sample in the freshlyprepared PPA solution had 100% of the oil removed, while the calciumcarbonate sample in the aged PPA solution had only 50% of the oilremoved. This result, compared to Example 19, demonstrates that the PPAis more effective as a chisel at 50° C. than at 20° C. for speed andefficiency of oil removal. The result in Example 20 also demonstratesthat the performance of PPA declines faster at elevated temperatures,likely due to hydrolysis of the PPA.

Example 21 Comparison of the Efficiency of Materials ContainingPhosphoric or Phosphonic Groups to Remove Oil from Calcium CarbonateSurfaces

This example demonstrates the efficiency of polyphosphoric acid inremoving oil from a carbonate surface in comparison to other chemicalscontaining phosphoric or phosphonic groups.

Several vials were prepared containing approximately 2 g of the “oil-wetCaCO₃ particles”, described above, and 4 ml of the aqueous testsolutions as shown in Table 8. In all the cases the aqueous solutionscontain 1 wt % of Tergitol 15-S-40 and 1.57 mmol % (mmol per 100 mL) ofphosphoric/phosphonic groups. The only difference between the testsolutions was the chemical that carries the phosphoric/phosphonicgroups. Table 8 lists the aqueous solutions used in this example.

TABLE 8 Test solutions containing 1 wt % of Tergitol 15-S-40 and 1.57mmol % of phosphoric/phosphonic groups. Experiment #Phosphoric/phosphonic-containing chemical 21.1 Polyphosphoric acid 21.2Phosphoric acid 21.3 Glycerol phosphate-di-Na salt 21.4 Glycerolphosphate 21.5 Diethylenetriamine pentakis (methylphosphonic acid)

The vials were placed in an oven at 40° C. and the percentage of thecleaned carbonate particles was estimated visually after 2 days. Table 9shows the results of the test.

TABLE 9 Percentage of cleaned carbonate particles after 2 days.Experiment # % of clean particles 21.1 100 21.2 0 21.3 0 21.4 10 21.5 25

This Example shows an advantage in using polyphosphoric acid overphosphoric acid in removing oil from calcium carbonate surfaces. Theexample also compares the performance of glycerol phosphate, which is asmall organic molecule containing one phosphate group, to Polyphosphoricacid which has several phosphate groups per chain. As shown in theExample, glycerol phosphate removes relatively little oil from thecarbonate surface in either the salt or acid form. The Example alsocompared the performance of an organic molecule containing 5 phosphonicgroups branched from the center of the molecule to polyphosphoric acidwhich is a linear structure of phosphoric groups. The polyphosphoricacid shows an advantage over the Diethylenetriamine pentakis(methylphosphonic acid).

EQUIVALENTS

While specific embodiments of the subject invention have been discussed,the above specification is illustrative and not restrictive. Manyvariations of the invention will become apparent to those skilled in theart upon review of this specification. Unless otherwise indicated, allnumbers expressing quantities of ingredients, reaction conditions, andso forth used in the specification and claims are to be understood asbeing modified in all instances by the term “about.” Accordingly, unlessindicated to the contrary, the numerical parameters set forth herein areapproximations that can vary depending upon the desired propertiessought to be obtained by the present invention.

While this invention has been particularly shown and described withreferences to preferred embodiments thereof, it will be understood bythose skilled in the art that various changes in form and details may bemade therein without departing from the scope of the inventionencompassed by the appended claims.

1. A formulation for facilitating the removal of oil from a surface,comprising: a chisel composition, wherein the chisel compositioncomprises a polymer having one or more binding points with a highaffinity for the surface, and one or more hydrophilic segments that forma hydrophilic coating on the surface, rendering the surface water-wetand thereby facilitating the removal of oil from the surface.
 2. Theformulation of claim 1, wherein the surface comprises carbonate rock. 3.The formulation of claim 1, wherein the surface comprises a metal. 4.The formulation of claim 1, wherein the polymer comprises polyphosphoricacid (PPA).
 5. The formulation of claim 4, wherein the polymercomprising PPA is protected by a protective mechanism to form protectedPPA.
 6. The formulation of claim 1, wherein the polymer is afunctionalized polymer.
 7. The formulation of claim 1, wherein thefunctionalized polymer is protected by the protective mechanism to forma protected polymer.
 8. The formulation of claim 5, wherein theprotective mechanism is selected from the group consisting of polymerencapsulation, polymer entrapment within a matrix, and polymer maskingwith a masking agent.
 9. The formulation of claim 4, wherein the polymeris adapted for controlled release.
 10. The formulation of claim 9,wherein the controlled release is actuated by a triggering mechanism.11. The formulation of claim 9, wherein the controlled release isaccomplished by a mechanism selected from the group consisting ofdissolution, diffusion, pH change, ionic strength change and temperaturechange.
 12. The formulation of claim 6, wherein the functionalizedpolymer is end-functionalized.
 13. The formulation of claim 6, whereinthe functionalized polymer is functionalized along a polymer backbone.14. The formulation of claim 1, wherein the binding points have the highaffinity for CaCO₃.
 15. The formulation of claim 1, wherein the bindingpoints have the high affinity for silica.
 16. The formulation of claim1, further comprising a surfactant.
 17. A method of reducing theattachment of oil to a surface, comprising: providing the molecularchisel formulation of claim 1; and directing the molecular chiselformulation into contact with the surface, thereby providing a water-wetsurface that impairs the attachment of oil and reduces the attachment ofoil thereto.
 18. The method of claim 17, wherein the surface is selectedfrom the group consisting of a CaCO₃ surface, a silica surface, and ametal surface.
 19. The method of claim 17, further comprising the stepof exposing the surface to a surfactant prior to, simultaneous with, orfollowing the step of directing.
 20. A method for recovering oil from aformation containing oil retained on a rock surface, comprising:providing the molecular chisel formulation of claim 1; directing themolecular chisel to contact the rock surface, thereby rendering the rocksurface water wet and thereby impairing the attachment of oil thereto;and recovering oil from the formation after the attachment of the oil tothe surface has been impaired by the preceding step.
 21. A molecularchisel formulation, comprising the chisel composition of claim 1 and aprotective mechanism.
 22. The formulation of claim 21, wherein thechisel composition comprises PPA.
 23. The formulation of claim 21,wherein the protective mechanism is a controlled release mechanism. 24.The formulation of claim 21, wherein the protective mechanism delays thehydrolysis of the chisel composition.
 25. A method of mobilizing oilfrom a reservoir formation, comprising: providing an oil retrievalformulation comprising a fracturing fluid and the formulation of claim1; and fracturing the formation with the oil retrieval formulation,thereby mobilizing the oil for retrieval.
 26. A method of preventingdeposition of an oil on a surface, comprising: providing the formulationof claim 1; directing the formulation into contact with the surface; andexposing the surface to the formulation to prevent deposition of the oilthereupon.
 27. A method of facilitating the removal of oil residua froma near wellbore region, comprising: providing the formulation of claim1; and directing the formulation into contact with the near wellboreregion to impair attachment of the oil residua thereto, therebyloosening the oil residua from the attachment and facilitating theirremoval from the near wellbore region.
 28. The method of claim 27,wherein the oil residua comprise asphaltenes, paraffins or waxes.
 29. Anoil, produced by the method of claim
 20. 30. A retrieved oil, whereinthe retrieved oil is mobilized by the method of claim 25.